Stone Energy CEO Discusses Q4 2012 Results - Earnings Call Transcript

Feb.26.13 | About: Stone Energy (SGY)

Stone Energy Corporation (NYSE:SGY)

Q4 2012 Earnings Conference Call

February 26, 2013; 10:00 a.m. ET

Executives

David Welch - Chairman & Chief Executive Officer

Ken Beer - Executive Vice President & Chief Financial Officer

Analysts

Dave Kistler - Simmons & Company

Michael Glick - Johnson Rice

Chad Mabry - KLR Group

Curtis Trimble - Global Hunter Securities

Nick Pope - Dahlman Rose

Shawn Steven (ph) - Oppenheimer

Mario Barraza - Tuohy Brothers

Hubert van der Heijden - Tudor Pickering Holt

Operator

Good morning. My name is Stephanie and I will be your conference operator today. At this time I would like to welcome everyone to the fourth quarter and year-end 2012 earnings conference call.

All lines have been placed on mute to prevent any background noise. After the speakers remarks there will be a question-and-answer session. (Operator Instructions). Thank you.

I’d now like to turn the call over to David Welch, you may begin your conference.

David Welch

Okay, thank you very much Stephanie and welcome everyone once again to our 2012 year-end earnings conference call. Joining us this morning is Ken Beer, Executive Vice President and Chief Financial Officer. Ken will discuss our financial results and then turn it back to me to discuss our progress implementing our strategic plan. After that we will be happy to answer your questions. So Ken.

Ken Beer

Thanks Dave, let me start with the forward-looking statement. In this conference call we may make forward-looking statements within the meaning of the Securities Act of 1933 and Securities Exchange Act of 1934. These forward-looking statements are subject to all the risks and uncertainties normally incident to the exploration for and development and production and sales of oil and natural gas.

We urge you to read our 2012 Annual Report on 10-K that will be filed later this week for a discussion of the risks that could cause our actual results to differ materially from those and any forward-looking statements we may make today.

In addition, in this call we may refer to financial measures that may be deemed non-GAAP financial measures as defined under the exchange act. Please refer to the press release we issued yesterday, which is posted on our website for a reconciliation of the differences between these financial measures and the most directly comparable GAAP financial measures.

With that out of the way, I’ll move forward. Again, I won’t go through the year 2012 year-end financials in great detail, but assume you’ve read the press release and the attached financials and we’ll try to focus on some selected items on the call.

Our discretionary cash flow for the quarter was $154 million or over $3 per share and for the year it was just under $620 million or a bad debt of $12.60 or so per share. The earnings for the quarter were $44 million or $0.89 per share and for the year earnings were $149 million or just over $3 per share; all of these results were well above the announced first call estimates. It’s just a good solid year with a good end of the year quarter.

Production for the quarter came in at 45,000 barrel equivalents per day or 270 million cubic feet equivalents at the upper end of our guidance and about 42,000 barrels per day or 252 million cubic feet equivalence for the year, with a split of approximately 46% oil, 8% NGOs and 46% natural gas.

Our production guidance for the first quarter 2013 is around 38,000 to 40,000 barrel equivalents per day or 230 mcf to 240 mcf per day. This is clearly lower than the fourth quarter 2012 production, primarily due to the Mary Field in Appalachia being down from virtually all of January and February.

As noted in the press release, after having heavy rainfall in late December that came in our Williams pipeline, which we produce into, experienced a couple of land slips on the hill side, which caused some pipeline damage for the Williams line. At first the repairs were thought to be relatively minor, but upon further investigation the decision was made by Williams to more fully repair the sections of the line.

Today the line has been repaired and although Williams has experienced some minor restart hiccups, we expect to be at full production in the Mary Field by early March. However this downtime affected approximately 60 million cubic feet day equivalence in volumes for January and February, clearly impacting our first quarter 2013 production, which will also impact our full year production guidance with a slight downward adjustment from a range of 41,000 to 44,000 barrels per day, down to the 40,000 to 43,000 barrels per day or 240 million, 255 million cubic equivalence per day for 2013.

We expect a little over 50% of the 2013 volumes to be natural gas with the remainder oil and NGO. Oil price utilization remained above $100 per barrel for the quarter and for the year as the Louisiana Sweet premium above WTI was over $20 for the quarter and $16 for the year. This positive differential continues into the first quarter of 2013, with LOS currently trading around $20 per barrel above WTI. Our NGO prices were just under $35 per barrel, as the NGO’s continue to be priced well below their historical ratio, the historical norm to the WTI.

Our realized natural gas price for the quarter was $3.40 or actually $3.80 after hedging. Not great, but certainly a lot better than the sub $3 and even sub $2 pricings we experienced back in 2012, early in that year.

On the cost side our LOE was about $58 million for the quarter and $215 million for the year. There was about $5 million in incremental major maintenance expenses in the fourth quarter tied to hurricane Isaac; we have noted about previously. And with the flattish production volumes projected in 2013, we are expecting LOE to also be flattish around the $215 million mark as well.

The transportation processing and gathering experience came in this year in the low end of our original guidance as $22 million to $28 million. We would expect this figure to trend up in 2013 with more transportation processing fees tied to volume increases in Appalachia, as well as higher pipeline transportation fees in the Gulf of Mexico. Guidance is $26 million to $32 million for 2013.

Our DD&A rate for the fourth quarter dropped to $3.32 per mcfe as the significant increase in our 2012 estimated group reserves caused a reduction in the DD&A rate from the previous quarters. This certainly helped with our favorable earnings results for the quarter and for the year. We are projecting that oil and gas DD&A rate to be in the $3.25 and $3.50 per mcf range, but certainly this is dependant upon several variables, including reserve additions and drilling success.

Accretion expense is projected to remain around $8.5 million or so per quarter for 2013. Our G&A before incentive compensation is running at just over $14 million per quarter as we’ve seen increases in personnel and salaries, particularly as we step up our deep-water efforts. We have adjusted our annual G&A guidance towards upwards, so it’s helped for that higher overall G&A run.

And then regarding interest expense we would expect the run rate for the reported interest expense to be around or just over $10 million per quarter with about $4 million of that being non-cash accrual paying some interest, primarily tied to the convertible notes accretion. This is something we’ve discussed previously. The October 2012 issuance of the $300 million of 7.5 senior notes due in 2022 would suggest a slightly higher run rate for interest expense for 2013.

Regarding taxes we ended up with around at a 36% tax rate. Although a little higher on current cash taxes than expected or projected, this was primarily due to stronger revenues leading to more income and a lower CapEx program than originally projected. We would expect our 2013 overall tax rate to be in that 36% to 37% range, with still a great majority of that being differed. However any subsequent changes to the tax code, including IBC deductions may impact this guidance.

As mentioned, our CapEx came in at about $580 million below the budgeted $625 million. Some of the late drilling project and the small acquisition that did not occur, actually kept us below the original figure.

Original varies. Its about $35 million positive adjustment from several items, including litigations in our favor and reimbursement on our promoted drilling projects and some other adjustments, which will have the effect of reducing the $583 million to a net cap or CapEx figure shown in our financials under about $550 million for the year. So the gross operates at $583 million, but it will come out and show a net number of about $550 million.

Our debt position today is $975 million, assuming a $300 million face value for the convertible notes or about $915 million if you use the recorded discount, a $240 million figure that converts. Our $400 million borrowing base on our bank facility remains un-drawn and we exited the year with over $250 million in cash. So really we’re in a very good liquidity position.

With that, I believe that warps up the financial overview and I’ll turn it over to you Dave.

David Welch

Okay, thank you very much. As you just heard it from Ken and saw in our press release, despite the performance of our stock price we had a very solid year.

Our production grew over 15% and we replaced 285% of our production, boosting reserves to an all-time high, despite the write off of over 50 bcf equivalents due to low natural gas prices. We also continue to generate sufficient cash flow that’s under our capital program, investing approximately $580 million in 2012, while generating about $620 million in cash.

Our balance sheet is strong with over $250 million in cash and an undrawn revolver of $400 million with no debt obligation to do until 2017. However given our outstanding opportunity set, we will likely outspend capital for the next couple of years as we continue to develop our three growth areas, Appalachia, Deep Water and liquids rich Deep Gulf Coast.

Ken has already discussed the production anomaly in the first quarter of this year, so I won’t re-hash it, but we’ll just add that it doesn’t feel to represent any material deviation from our long-term plan or strategy. Our strategy remains the same as it’s been for the last seven years, to pursue investment in price advantage nature gas and material oil projects. Also the diversification from the conventional Gulf shelf is nearly complete as the conventional shelf now represents less than 20% of our total proved reserves.

We grew reserves in all three of our growth areas this past year and sufficiently saw that we were able to overcome the price related write-down and still grow total company reserves by 28.4%. We began the year with about 100 million barrel of oil equivalent. We produced 15, wrote off 9 due to price, had upward well based performance revisions of about 15, added 31 with the drill bit and acquired 6 million barrel equivalents to end the year with approximately 128 million barrels of equivalent reserves.

Our proved reserve is about with 49% liquids and 51% natural gas. The 50 bcf of 9 million barrel equivalents of downward price related proved reserve revisions were spread across both the Gulf and Appalachia. The 15 million barrels of upward performance revisions comprised six in Appalachia at our Mary field, six in Deep Water at Pompano and three in the liquids rich Deep Gulf Coast at La Cantera.

The 31 million barrel equivalent proved reserve ad with the drill bit was primarily in our Mary Field in Appalachia and in the La Cantera field in the Gulf Coast. Our 15% production growth was also driven by increases at Mary in Appalachia, Pompano, Phinisi and Wideberth in Deep Water and La Cantera in the Gulf Coast.

So to sum up 2012, even though the external markets saw reduction in both oil and natural gas prices, the fundamentals of our business continue to improve. The improvement includes growth in liquidity, production and reserves.

This performance sets us up well for execution of our three-year plan. The three year plan includes limited drilling investment in the conventional shelf, continuation of our two rig program in Appalachia, which is composed of one horizontal and one vertical rig and accelerating investments in the deep liquids rich Gulf Coast and in Deep Water.

On the shelf we planned to drill about two to five oil wells a year, with the aim of a relatively stable liquids production rate, that are not trying to gown reserves there due to limited size of the remaining opportunities.

In Appalachia we see many years of development drilling ahead of us and for the next three years we plan to continue drilling 25 to 30 Marcellus wells per year at our liquids rich Mary Field.

We also planned to drill a horizontal well just past the upward Devonian Shale, which lies just above the Marcellus at Mary’s. But the upper Devonian is condensate rich and produces at commercial rates. It could materially enhance the value of our Appalachia assets.

In the liquids rich Deep Gulf Coast area, we are presently drilling another development well at La Cantera and expect to drill or participate in the drilling of two to four exploratory wells each of next three years. This is a very attractive play for us and that there are many good opportunities and when a discovery is made, it can be brought on to production quickly.

This year we hope to drill in La Montana and possibility Thunder Bayou and Permian Parish, Louisiana and possibly Tom Cat in the shallow waters offshore. All of these are exploration prospects, which are expected to offer high rate wells and materials liquids contents. Stone is the operator of La Montana and Tom Cat. We have several additional attractive prospects in our inventory and are keen to drill them in 2014 and 2015.

In deep waters lots of things are happening. We are preparing for what we believe will be significant increase in production over the next three years. Lets start with our Northern Mississippi Canyon corridor, anchored by two production hubs at Amberjack and Pompano. We’ve authorized the car donor development well and Amethyst exploration well tiebacks to the Pompano platform as our first company-operated deep water drilling wells. These wells should commence in 2014 and be on production in 2015 if it’s successful.

We are in the process of ordering long lead-time items, negotiating floating rig contract and are making platform modifications to the Pompano platform to accept both new tie-back wells and the platform rig. We are securing the platform rigs for both Pompano and Amberjack and expect to drill four to five wells from each of these platforms beginning in 2014 as well.

So we are poised for a material production growth in our company operated Mississippi Canyon corridor. In addition to this we expect to drill or participate in two to four exploration wells in Deep Water each of the next three years. This will begin this year, where we expect to participate in two or three exploration wells.

The follow year we anticipate our first company operated deep water exploration wells at our Amethyst prospect and to participate in the first well to be drilled under our previously announced Conoco joint venture.

The partnership at our Parmer discovery might be also ready to drill the next appraisal well there in 2014. So this is becoming a very active area for us and we are expecting significant growth in both oil production and oil reserves over the course of our three-year plan from deep water.

So to sum it up, we are moving forward successful on all fronts of our strategy plan. We are managing the Shelf decline and achieving growth in Appalachia, in the deep liquid rich Gulf Coast and in the deep water Gulf of Mexico.

To keep from being redundant with Ken’s remarks, lets stop here and we’ll now be happy to take your questions. Stephanie, back to you.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions). And your first question does come from the line of Dave Kistler of Simmons & Company. Your line is now open.

Dave Kistler - Simmons & Company

Good morning guys.

David Welch

Good morning Dave.

Dave Kistler - Simmons & Company

Really quickly looking at Pompano and the reduction in LOE about 20% this year, can you walk through a little bit what the big drivers of that reduction were and where you see that going forward in ’13 as well.

David Welch

Yes, a couple of things Dave. We’ve been doing a pretty good job on production efficiency keeping our wells online, mostly the time which was helpful. The other thing that we’ve done is we’ve stopped the program differently than BP did when BP was the operator.

We’ve mainly made up the, its about $10 million a year savings in LOE; that’s mainly been made up by being more efficient in terms of our deployment of our human capital, as well as some logistical synergies we got both in helicopters from operating the Amberjack platform near by, so that’s a big driver.

And I think we just about captured most of the efficiencies from operating the field. As we bring more production through there, we could still see a further unit cost reduction.

Dave Kistler - Simmons & Company

Okay, that’s helpful and that’s a good segway to the next question, thinking about increases in production from Pompano. It looks like you guys did a bunch of well intervention works specifically on the A10 and A28 wells. Is there a lot more of that type of work that can be done in ’13 and naturally that factored into your ‘13 guidance at this point.

David Welch

Yes, so we do have it factored into our guidance Dave. Of course there is always a change we can be more or less successful than we figured, but we have an ongoing program of interventions out there. I don’t know of any really huge wells that are going to be changing the profile dramatically though.

Dave Kistler - Simmons & Company

Okay, that’s helpful and then maybe one last one, just on the Shelf target that you highlighted in your comments and in the release. Can you talk about the size of those targets and the kind of inventory that’s available, both internally or that you may have to be looking to purchase to kind of keep that production level flat that you talked about.

David Welch

Yes, we’ve got about four, five wells to drill on the Shelf this year and that may even decline a little bit going forward over the next three years. As some of our other production ramps up, the Shelf would just be a little bit smaller component of our production. It’s already less than 20% of our reserves.

But we are focused on drilling oil wells on them. We are not drilling any gas prospects on the Shelf, because the target size just feels too small to take much risk. So we are concentrating on development type wells that carry a high percentage success rate and then we are also focused on oil. So there won’t be a whole lot of drilling that we’ll be doing on the shelf and I think that four to five wells a year is probably about how far we feel we can push it and still have high economic returns.

Dave Kistler - Simmons & Company

Okay, just one clarification on that. What are kind of the sizes of those oil targets or oil development wells that you are drilling on.

David Welch

These things on the shelf, they are typically less than 1 million barrels. They range from 300,000 to 600,000 barrels typically.

Dave Kistler - Simmons & Company

Okay. I appreciate the additional color there. Thanks so much.

David Welch

You bet.

Operator

And your next question comes from line of Michael Glick of Johnson Rice. Your line is now open.

Michael Glick – Johnson Rice

Good morning.

David Welch

Good morning.

Mike Glick – Johnson Rice

Just a couple of kind of strategic questions. As you move towards an operative program in the deep waters, just curious what your appetite for risk there is. Should we kind of think about it as the lower risk development type wells? Like Cardona you will keep the majority of your working interest, whereas there is some of the exploration type targets like Amethyst you may look to bring in a partner.

David Welch

That’s pretty good analysis. Cardona, we do have about a 65% working interest in that already and we could handle that if a good enough deal comes along, we might do even something on Cardona. But at Amethyst, the exploration well, we’ll certainly be looking for a partner there and we think it’s a good prospect that hopefully would bring someone willing to pay or promote to get in on that prospect and others that we have in the Pompano area.

Mike Glick – Johnson Rice

Okay, and then as we look over the next few years, deep water capital commitments are going to grow pretty significantly, especially if you do have some exploration success. And given the Shelf’s kind of lower profile in terms of reserves, is that something you consider monetizing at some point to help fund the deep-water activities.

David Welch

I think we’ve got a few core properties on the shelf that I can see us wanting to hold on to, but there is some others that at that perfect time we might consider some type of a market test. I don’t think we’d sell them under a par sale. I think there are other ways for us to get capital rather than giving up value. But the tail properties on the Shelf, that’s something we’d certainly consider.

Mike Glick – Johnson Rice

Okay, thank you.

David Welch

You bet.

Operator

And your next question comes from the line of Chad Mabry of the KLR Group. Your line is now open.

Chad Mabry - KLR Group

Thanks. Good morning. Just had a couple of quick questions on some of the newer deep water prospects, San Marcos, Guadalupe, can you provide your resource potential estimates or your potential cost estimates for those prospects.

David Welch

I don’t believe we have provided those. They are operated by Apache, and Apache may have put out some numbers on those that I could refer you to.

Ken Beer

Yes Chad, we’ll probably follow up their lead. But I think its efficient to say that these are more of a tie-back in nature as opposed to substantial 100-plus million barrel swings, so I think that’s the way to think about. But again, this is one more where Apache provides a lead and we’ll come in behind their comments.

Chad Mabry - KLR Group

Okay, that’s helpful. I appreciate it. And then just a quick follow up; I was wondering if you could elaborate on the status of some of your on shore oil initiatives; anything to expect there in the near term?

David Welch

We are always looking for something there. I guess the one thing I can say is that we have a couple of them that we are talking about right now, but there is nothing really material to report to you at this time or we would do it.

Chad Mabry - KLR Group

Okay, thanks guys. Great quarter.

David Welch

You bet.

Ken Beer

Thanks Chad.

Operator

(Operator Instructions). And your next question does come from the line of Curtis Trimble of Global Hunter. Your line is now open.

Curtis Trimble – Global Hunter Securities

Good morning everyone. I just was hoping you might be able to give us a little bit of a taste of what you are looking for at Hyena in terms of prospect size, the real extent of depth, etcetera.

David Welch

I’m sorry, could you say that again.

Curtis Trimble – Global Hunter Securities

Metrics on the Hyena prospect, that the…

David Welch

Oh, the Hyena, the on shore, yes that’s a small prospect. Again, its one of these fairly high probability of working, but the reserve size on it is going to be well under a million barrels. So it’s just something that can give us some additional rate in cash flow and quick pay out. So it’s not a strategic investment, its just kind of a single.

Ken Beer

I mean, this is not to be confused with on shore deep project or prospect. This is a real conventional and kind of a …

David Welch

Development well in an existing field is all it is.

Curtis Trimble – Global Hunter Securities

Well understood.

David Welch

Okay.

Curtis Trimble – Global Hunter Securities

Also just, I hate it to be a too short term this year, but looking at net gas pricing dynamics in the context of the Mary Field, what would you think realizations might materialize and do you proceed in the impact from the deferrals there at Mary on to your net gas realized price.

Ken Beer

Again, in that area, ultimately we are flowing into the Williams line and then going into the Tetco line. So the pricing there as you know is going to come down so that it’s pretty close to Henry Hub pricing. Again, two or three years ago we would have expected a premium, but we still are getting effectively the Henry Hub high pricing.

One of the very attractive features of the Mary Field is besides nature gas pricing we also do have a fair amount of liquids, both condensate and NGL liquids. So our effective price for natural gas if you put both condensate and NGL’s into that price, it gets beyond that $3.40 and into the $5 and then hopefully even $6 price currency FD equivalent.

Curtis Trimble – Global Hunter Securities

Good deal. I appreciate the color.

Ken Beer

Great. Thank you Curtis.

Operator

And your next question comes from the lien of Michael Glick of Johnson Rice. Your line is now open.

Michael Glick - Johnson Rice

Hey guys, this is just a quick kind of follow up. You talked about adding platform rigs at Pompano and Amberjack. I was just curious kind of what the timing there could look like? I mean would you have two platform rigs working at those fields and then in terms of Amberjack, how are you looking in terms of well slots out there?

David Welch

We have slots at both platforms that we can use to execute our program with. The rigs themselves, we had verbal agreements for our particular rig to in there, just waiting its availability. It could come as early as second or third quarter of 2014 and its possible we could certainly manage the operation of both rigs at the same time, but its more likely that just rig availability will help them with either a small overlap or sequentially.

Michael Glick - Johnson Rice

Okay, that’s helpful. Thank you.

Operator

And your next question comes from Nick Pope of Dahlman Rose. Your line is now open.

Nick Pope - Dahlman Rose

Good morning guys.

Ken Beer

Good morning.

Nick Pope - Dahlman Rose

Hey, just looking at the deep-water exploration projects you have, I guess there’s a lot kind of on tap for late 2013 early 2014. I’m just curious, in terms of the development and its success case, what’s the primary sub-sea tie back or are you going to need to put in new platforms in the success case.

And I guess what are the thought processes going forward. I mean it’s obviously a positive scenario. But is the success case, how would you think about funding kind of maybe multiple of these prospects, kind of on a more of a development phase going forward.

David Welch

Sure, I’ll take the first part and Ken can take the last part. You are right, we have most of these prospects that are listed in our press release or tied-back type opportunities. Cardona would be tied back to our Pompano field. We own that and control that, so that’s no problem; San Marcos in Guadalupe, unless we get surprised to the large upside, those are also likely tied backs.

And then the Phinisi deep water, Walker Ridge prospect, that’s out right in between Jack and St. Malo and our big hub facilities going in just two or three miles from where that’s located. So that would also be a convenient tie back if the commercial deal could be worked out. So most of them that you see here are tied back situations.

Ken, if you want to talk a little bit about the financing of those, I think we have a lot of options.

Ken Beer

And that actually is the key and its one of the reasons why we really wanted to enter 2013 in such a strong position. As noted we’re well over $250 million cash. We have an unused facility. We can follow the discover and dilute down strategy. We can continue to fund using debt and/or equity. We can look to bring in our financial partners specific to some of these deep-water projects; we can look to bring in an industry partner.

So we think we’ve got a lot of options ahead of us and that’s one of the reasons why we really did want to make sure our balance sheet and financial position was in real good as we hopefully will get to that decision for you and have to fund success. We certainly want to fund it from a position of strength, not in our weakness.

Nick Pope - Dahlman Rose

Okay, that’s really helpful. Good luck on it. Thanks guys.

David Welch

Thank you.

Operator

And your next question comes from the line of Shawn Steven (ph) of Oppenheimer. Your line is now open.

Shawn Steven (ph) - Oppenheimer

Great. Thank you and good morning.

Ken Beer

Good morning.

Shawn Steven (ph) - Oppenheimer

Most of my questions were answered, but do any of your Appalachia plans this year include wells at Christine or Katie.

David Welch

Not likely, we don’t have anything on the plan right now for Katie.

Ken Beer

As you know, Katie is really a pure dry gas area and although there have been some pretty substantial wells up there, we don’t have a real big, big position and the thought was instead of diverting our operations and time and attention, the focus is just really on Mary which really does have the liquids and condensate associate with it.

And quite honestly, we know that we are getting more and more efficient in that West Virginia path drilling as opposed to Katie. Again, we just don’t have it set up right now, to be as efficient as we would be in Mary and certainly would look for and hope that even from this point, even a small rise in gas prices might allow us to take a harder look at the Katie field.

Shawn Steven (ph) – Oppenheimer

Right, that makes sense. And do you guys face any lease expiration issues this year.

David Welch

Appalachian you referring to.

Shawn Steven (ph) - Oppenheimer

Right, yes, yes.

David Welch

No nothing serious.

Shawn Steven (ph) - Oppenheimer

Okay and so just judging from your comments there Ken, you would say any sort of small increase from the current strip on the gas side you might look to drill at Katie, is that fare.

Ken Beer

Yes probably, certainly there is nothing planned in 2013 and we’d not expect that plan to change. Its just, I’m guess I’m highlighting it as more tied to gas prices, because it is purely a dry gas regime and so we’d certainly want to just get more and more comfortable with gas prices being higher rather than looking back at 2012 when we saw the three meet in the sub-threes.

Shawn Stevens – Oppenheimer

Okay, great. Thank you very much.

Ken Beer

Thank you.

Operator

And your next question comes from the line of Mario Barraza of the Tuohy Brothers. Your line is now open.

Mario Barraza - Tuohy Brothers

Good morning guys.

Ken Beer

Mario, how are you doing?

Mario Barraza - Tuohy Brothers

Good thanks. What’s your plan to ramp up in activity in the Gulf of Mexico? Looking at your onshore oil, with your plans looking at outspent CapEx in the next couple of years, how you’d consider these plays as part of your portfolio going forward.

David Welch

Are you referring to new plays?

Mario Barraza - Tuohy Brothers

Yes, the Niobrara, the Bakken and the Paradox.

David Welch

Yes, we are not allocating any capital to speak off to those projects at all. In fact we’re actually trying to do some deals to maybe even get out of those. So they are not an important part of our portfolio any longer.

Mario Barraza - Tuohy Brothers

Okay, is that something you’d like to – so, you’re in the process of trying to do some deals right now?

Ken Beer

Yes again, if you remember these are areas that we haven’t spent a ton of capital. We really went in with the thought if we could turn these into cookie cutter on shore projects, that was the goal and in the case of the Cane Creek area, we really are not pushing forward right now with additional capital. The case with Eagle Ford as you might remember, we don’t have a big enough position there to make it meaningful; in case of the Alberta Bakken, we really are not up with new fields.

So really are not, as they pointed out, not putting a whole lot of capital or man-power into those efforts that they’ve alluded to. But we do have out antenna up and continue to look for projects that might fit the description of our insurer, our little cookie cutter, but again Mario, I think you will see that as minimal capital during 2013. You probably won’t see it and you probably won’t be talking about anything until we feel more comfortable that it’s a place that we would put capital.

Mario Barraza - Tuohy Brothers

All right, I appreciate the color guys.

Ken Beer

Yes.

Operator

And your next question comes from the line of Hubert van der Heijden of Tudor Pickering Holt. Your line is now open.

Hubert van der Heijden – Tudor Pickering Holt

When you see given the comments that you made about it being a tie back project, that on a relative basis to your Apache operated tie back opportunity, this is still I guess in order of magnitude so to say bigger than those. The NEC is still considered a large shale and gold type opportunity correct.

David Welch

Yes, for me these are a little bit bigger, although what I would say is there is overlapping ranges. There is such a wide range of what these could be until you drill them and really understand how sizable they might be, its pretty difficult to frame them up on a discreet basis, but the range of Phinisi is larger than the other. The upper end of Phinisi is larger than the others.

Hubert van der Heijden – Tudor Pickering Holt

Okay. And I guess, could you also switch into Appalachia, can you talk a little bit about the marketing efforts that your pursuing on the condensate site for the Northeast.

Ken Beer

Yes, that as I’m sure your aware of, that has been just from a pricing standpoint certainly the condensate takes the effect of pricing of the gas stream and pushes it upward pretty dramatically. Having said that it still was trading at a fairly severe discount off of WTI. So obviously in the Gulf Coast we are getting a $20 premium and less than WTI and Appalachia is probably just the reverse.

Again, a lot of this is just a transportation hit that we are taking. We are doing some things to try to lessen than hit and certainly as we have more volumes that helps, but I would not expect to see this somewhat discounted pricing scheme disappear. I think just for our planning purposes, even though the condensate itself is very, very high quality you know, 80 API type condensate, the storage and transportation is actually a cost and we would see some sort of $15, $20 $12 discount off of WTI to continue.

Hubert van der Heijden – Tudor Pickering Holt

Okay, perfect. Thank you.

Ken Beer

Okay.

Operator

And we have no further questions in queue. I will turn the call back to the presenters.

David Welch

Okay, thank you very much Stephanie and thank you everyone for joining our call and for your interest in Stone. We’ll talk to you next time. So long.

Ken Beer

Take care.

Operator

Well, this concludes today’s conference call. You may now disconnect.

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Stone Energy (SGY): Q4 EPS of $0.89 beats by $0.34. Revenue of $255M beats by $18M. (PR)